1. Field of the Invention
This invention relates generally to oil producing operations, and more particularly to a system and a method for monitoring and controlling foam or hydrocarbon carry over at a wellsite.
2. Background of the Invention
Oil, also referred to herein interchangeably as crude oil, condensate, or formation fluid, in essentially all reservoirs contains at least some dissolved gases, which exist naturally in the formation. When oil flows upward from the formation through the wellbore(s) to the wellhead, there is a substantial decrease in the pressure because the platform equipment is set up to reduce the high reservoir pressure to a pressure that can be handled by a pipeline system or other downstream equipment. As a result of this drop in system pressure, some of the dissolved gases tend to evolve and become physically separated from the oil to form gas bubbles, i.e. foams.
Although the amount of gases originally dissolved in the oil may not be very large, the effect of lower pressure on their separation can be quite substantial. This is because the same weight of a gas occupies a much larger volume than the corresponding liquid. Depending on the molecular weight, temperature and other conditions, it is not unusual for a small amount of liquid to transform into gas with 100 times or even higher volume. Examples of commonly encountered and naturally occurring gases in formation fluid include, but are not limited to, methane, ethane, carbon dioxide and mixtures.
There is typically a train of several liquid and gas separators installed at a wellsite to separate gases from the oil (liquid) before the oil is processed or transported. In an ideal situation, the evolved gases and oil should separate relatively fast because they are in separate phases and the gas phase bubbles should break out of the fluid phase readily. For a number of reasons, however, the oil-gas separation in practice is usually difficult and incomplete. The main reason is that the gas bubbles in the oil (also referred to as emulsions or foams) are too stable to be effectively broken up at a high oil production rate even with several gas-oil separators because the residence time of the liquid in each separator is kept relatively short. In view of the fact that the industry trend is to have even higher production rate from a producing well, i.e even shorter residence times in the separators, and drilling into formations in deeper water, the problem with foaming may become even more severe. While it is certainly possible to build and use larger gas-oil separators, this option may not be desirable or practical because such separators would require much higher capital investments and more space on oilfield platforms.
Foaming is undesirable because it is usually an unpredictable and metastable phenomenon, which may interfere with the gas-oil separation efficiency or the operations of the oil well(s); the resultant carryover of liquid in the form of either foam or mist/droplets of oil entrained in the gas stream exiting the gas-oil separators will enter into downstream equipment or pipeline. Too much of such liquid carryover can cause severe operating problems, such as flooding for the downstream gas transportation equipment, pipeline or gas processing plants.
One reason for the existence of stable foam, thus the foaming problem, is that many surfactants exist naturally in or near the producing formations. Such surfactants, with their ability to stabilize emulsions or foams, cause the foaming problem to become more pronounced and longer lasting, particularly when the formation fluid reaches the production facilities at the wellhead on the surface as noted above. Moreover, many chemicals or additives are injected into oil wells by the operator to provide functions such as corrosion inhibition, asphaltenes suppression, etc. and may also act as surfactants under the producing conditions to further stabilize the emulsions, thus exacerbating the foaming problem.
Another factor affecting foaming occurs when the formation fluid flows from the producing formation toward the wellbores of the producing wells. The flow rate near the wellbores becomes higher than that in other parts of the reservoir. This higher flow rate tends to cause the formation fluid to trap and mix with any water that may be in the vicinity of the wellbore, or any steam that is injected into the wellbore by the operator. In the presence of either natural or injected chemicals behaving as a surfactant, this type of oil-water emulsion also can further intensify the foaming problem at or down stream from the wellhead.
In typical land or offshore oil production wells, the formation fluid from the wellbores flows through a wellhead choke into a high pressure manifold, which is used if there are multiple wells at a particular site. The fluid then passes through one or more heat exchangers to recover useable heat into a high-pressure (HP) gas-oil separator. There are usually several separatorsxe2x80x94a train of separatorsxe2x80x94for one oil processing platform. The primary functions of these separators are to separate the gas and liquid components of the oil and to reduce the pressure in a stepwise manner. Such a train of separators commonly comprises a HP separator, an intermediate pressure (IP) separator, a low-pressure (LP) separator, and a test separator, with the HP separator being closest to the wellhead choke and having the largest pressure drop. In order to conserve energy by not having to repressurize, it is preferred to separate gas from oil at as high a pressure as possible.
The gas phase of the production fluid rapidly expands downstream of the wellhead choke, and continues to expand further downstream through pressure control valves as the fluid travels through the train of gas-oil separators. Any natural surfactants or other additives injected into the well which can act as surfactants tend to create a foaming problem more often in separator vessels with rapid pressure drops, such as the HP separator which have the greatest pressure drop, than the remaining separators in the train of separation.
It is therefore desirable to have a reliable system to determine the extent of foaming of the formation fluid recovered through a wellbore at the wellsite. It is also desirable to use the obtained foaming information to control foaming at the wellsite. The present invention addresses the above-noted needs and provides a wellsite foam monitoring and controlling system which (a) determines the extent of foaming, (b) determines the extent of the treatment required to alleviate the foaming problem, and (c) controls the dispensing of additives to inhibit or alleviate the foaming problem.
The present invention provides a system for determining and controlling foaming, particularly at a wellsite, of a formation fluid passing through at least one liquid and gas separator that provides a gas stream separated from the formation fluid. The system comprises a sensor, such as a densitometer or a transmission probe, for providing measurements of a parameter of interest relating to the gas stream that are indicative of foaming of the formation fluid, and a processor utilizing the sensor measurements for determining degree of foaming of the formation fluid.
The present invention also relates the aforementioned system which further comprises a gas separation device, such as a quill, for separating a portion of gas, a side stream, from the gas stream and the sensor provides the measurements utilizing the side stream. In another embodiment of the present invention, the sensor is a particle-detecting sensor based on light scatter or transmission configured in the above described sidestream technique or by insertion of a transmission probe directly into the vessel or pipeline.
In another aspect of the invention, there is a chemical injection unit for supplying a chemical to the formation fluid for optionally controlling foam of the formation fluid. The chemical injection unit injects the chemical at one or more of the following location; (i) in one or more of the liquid gas separators; (ii) in a well producing the formation fluid; (iii) a wellhead at the surface; (iv) a selected number of wells from a plurality of wells providing formation fluid to the separator(s). The chemical injection is increased when the degree of foaming is outside a predefined limit.